This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This description is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulfide (H2S) and carbon dioxide (CO2). When H2S or CO2 are produced as part of a hydrocarbon gas stream, such as methane or ethane, the raw natural gas is sometimes referred to as a “sour” natural gas. The H2S and CO2 are often referred to together as “acid gases.”
Sour natural gas must be treated to remove the H2S and CO2 before it can be used as an environmentally-acceptable fuel. As an example, for LNG, the H2S and CO2 must be removed to very low levels, e.g., less than about 50 parts per million by volume (ppmv) CO2 and less than about 4 ppmv H2S. As another example, for pipeline gas, the H2S must be removed to a very low level, e.g., less than about 4 ppmv, while the CO2 may be removed to a lesser extent.
Cryogenic gas processes are sometimes used to remove CO2 from raw natural gas stream to prevent line freezing and orifice plugging. In addition, particularly with H2S removal, the hydrocarbon fluid stream may be treated with a solvent. Solvents may include chemical solvents such as amines. Examples of amines used in sour gas treatment include monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA).
Physical solvents are sometimes used in lieu of amine solvents. Examples include Selexol® and Rectisol™. In some instances, hybrid solvents, meaning mixtures of physical and chemical solvents, have been used. An example is Sulfinol®. In addition, the use of amine-based acid gas removal solvents is common.
Amine-based solvents rely on a chemical reaction with the acid gases. The reaction process is sometimes referred to as “gas sweetening.” Such chemical reactions are generally more effective than the physical-based solvents, particularly at feed gas pressures below about 300 psia (2.07 MPa). There are instances where special chemical solvents such as Flexsorb™ are used, particularly for selectively removing H2S from CO2-containing gas streams.
As a result of the gas sweetening process, a treated or “sweetened” gas stream is created. The sweetened gas stream is substantially depleted of H2S and CO2. The sweetened gas stream can be further processed for liquids recovery, that is, by condensing out heavier hydrocarbon gases. The sweetened gas stream may be sold into a pipeline or may be used for liquefied natural gas (LNG) feed if the concentrations of H2S and CO2 are low enough. In addition, the sweetened gas stream may be used as feedstock for a gas-to-liquids process, and then ultimately used to make waxes, butanes, lubricants, glycols, or other petroleum-based products.
Known counter-current contactors used for removing H2S and CO2 from natural gas streams tend to be large and very heavy. This creates particular difficulty in offshore oil and gas production applications, where smaller equipment is desirable. Further, the transport and set-up of large tower-based facilities is difficult for shale gas production operations that frequently take place in remote locations.
The removal of H2S and CO2 from a natural gas stream produces a rich solvent including the H2S and CO2. The rich solvent is sometimes referred to as an absorbent liquid. Following removal of the H2S and CO2, a process of regeneration (also called “desorption”) may be employed to separate the H2S and CO2 from the active solvent of the absorbent liquid. This produces a lean solvent.
Regeneration of the lean solvent generates a concentrated mixture of the H2S and CO2, typically at around 15 psig. In some cases, this mixture can be sent to a Claus sulfur recovery unit to convert the H2S to elemental sulfur. However, in many cases, the high ratio of CO2 to H2S renders the mixture unsuitable for use as a Claus feed stream. In such cases, the acid gas must be enriched prior to being used as a Claus feed stream. This may be accomplished via a low pressure enrichment process that uses a selective amine to preferentially absorb H2S. In principle, the remaining gas in this case could be used as a substantially clean (although low pressure) CO2 stream.
Alternatively, a “super-selective” H2S removal process may be used on a sour gas stream to remove substantially all of the H2S, and to generate a concentrated acid gas stream suitable for Claus feed. This would obviate the need for an acid gas enrichment (AGE) unit, saving substantial costs. A subsequent CO2 removal process could be used to generate a substantially clean CO2 stream, as well as sweetened natural gas. The extracted CO2 may then be sold, or it may be injected into a subterranean reservoir for enhanced oil recovery (EOR) operations.
U.S. Patent Application Publication No. 2009/0241778 by Lechnick et al. describes a system for removing CO2 from a feed gas within an absorber unit that contains a solvent, and regenerating the solvent within an eductor. However, because the absorber unit and eductor are likely to be large and very heavy, such a system may be expensive and undesirable, particularly for offshore oil and gas recovery applications.